Conceptual Design Of Salt Cavern Based Lng Terminal

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The United States Department of Energy National Energy Technology Laboratory

24 April 2003

Report II: “Conceptual Design of a Salt Cavern Based LNG Terminal”

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CONCEPTUAL DESIGN OF A SALT CAVERN BASED LNG TERMINAL

BY MICHAEL M. MCCALL WILLIAM M. BISHOP D. BRAXTON SCHERZ

r 1.0

For client review

24/04/03

Version

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Document Title: Conceptual Design of a Salt Cavern LNG Terminal

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Review

Document No: CGI/DOE_DOC 06 DE-FC26-02NT41653 Filename: 41653R01

Customer:

Document Title:

The United States Department of Energy National Energy Technology Laboratory Report II: “Conceptual Design of a Salt Cavern Based LNG Terminal”

Date of Issue:

24 April 2003 Doc # & Version:

Doc 06 r1.0

Page 2 of 13

TABLE OF CONTENTS

1. EXECUTIVE SUMMARY ..................................................................................................................................3 2. THE LNG ONSHORE TERMINAL ...................................................................................................................4 2.1.

BPT LNG Terminal - Process Flow Diagram ............................................................................ 6

2.2.

List of Critical Machinery ........................................................................................................... 7

2.3.

Estimated Costs and Revenues ................................................................................................ 8

3. THE LNG OFFSHORE TERMINAL................................................................................................................10 3.1.

Conceptual Layout.................................................................................................................... 10

3.2.

Offshore Terminal - Estimated Cost and Revenue................................................................ 12

Filename: 41653R01

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Document Title:

The United States Department of Energy National Energy Technology Laboratory Report II: “Conceptual Design of a Salt Cavern Based LNG Terminal”

Date of Issue:

24 April 2003 Doc # & Version:

Doc 06 r1.0

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1. EXECUTIVE SUMMARY Numerical modeling, finite element analysis, and reviews by experts specialized in pipe-in-pipe technology confirmed the feasibility of the using salt cavern in the receipt of LNG. The study team used the critical elements referenced in Task 1.0 to conceptually design two LNG receiving terminals, (1) an onshore terminal capable of economic, safe, and reliable LNG transfer and regasification, and (2) an offshore terminal using the identified elements required to transfer and regasify LNG safely, reliably, and economically. A specific site was identified for both terminals. The onshore terminal is located at the mouth of the Calcasieu River, in Cameron Parrish, Louisiana. The offshore terminal is located in the Gulf of Mexico over Vermillion Block 179, about 50 miles south of Interstate City, Louisiana. Each of the following conceptual LNG receiving terminal are designed according to the known environmental surroundings of the sites. Both terminals employ the BPT exchanger, associated pumping equipment, and utilize salt caverns for storage. All cost estimates are site specific and are accurate to within ± 35%. The Onshore Terminal uses proven technology. Other than the pumping and regasification process already discussed, the marine unloading facility represents little departure from typical LNG receiving terminal. The marine berth and Ship to Shore interface are quite familiar to the industry, and docking/undocking methods are accepted world wide. Because the LNG industry is familiar with the critical components, the BPT onshore terminal will most likely be the first terminal constructed. Based on a throughput cost of service of $0.096 per mmBtu, the conceptual “Liberty” land based terminal has an internal rate of return of 15.0%. LNG offshore is coming, and coming quickly. The concept of moving LNG offshore is at least 30 years old, and the methodologies of LNG at-sea transfer will be almost identical to the procedures developed for the offshore oil industry. Design firms, E&C companies, and experts having a thorough insight of the transfer of oil and LPG offshore, realize that the technologies to handle cryogenic materials will have to be further developed and refined. All imminently workable LNG offshore solutions in various stages of testing or fabrication are based on this understanding. This section of the study reveals that the proposed conceptual offshore terminal is competitive in terms of total installed cost, operation and maintenance. The throughput fee and rate of return are similar to the onshore design, and both are advantageous compared to conventional LNG terminals with similar capacities. Based on the same pro forma economic evaluation, the conceptual offshore terminal generates a 15% internal rate of return on a throughput cost of service of $0.095 mmBtu. Additional study and development of the key components (cryogenic swivels, flexible transfer systems, and cryogenic subsea piping), further wave tank modeling, and industry willingness to “risk” moving LNG offshore are required before an LNG at-sea can become a reality. However, if the total install cost for the terminal can be kept within the reasonable estimates of this study, an LNG offshore terminal could be built by 2006.

Filename: 41653R01

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The United States Department of Energy National Energy Technology Laboratory

24 April 2003

Report II: “Conceptual Design of a Salt Cavern Based LNG Terminal”

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2. THE LNG ONSHORE TERMINAL By design the BPT LNG receiving terminal is capable of sending out as much as 3.0 Bcfd from the salt storage caverns. The process itself is capable of regasifying as much as 3.8 Bcfd. To provide the large volumes of LNG necessary to help mitigate the natural gas shortfall projected by the EIA, CERA, and others, the LNG terminal must be located near a pipeline infrastructure capable of sufficient capacity to take advantage of the BPT terminal’s substantial send-out capability. Knowing that some of the nation’s largest pipelines pass through an area in South Louisiana known as “Henry Hub,” the Study Team assembled various maps and charts of the Louisiana Gulf Coast and identified several areas along the Calcasieu River as likely candidates for siting a BPT LNG receiving terminal. In addition to the advantages offered by a site close to the massive natural gas transportation system, a BPT terminal located along the Calcasieu River could take advantage of any existing salt caverns that might also be in close proximity. Salt caverns have been used for hydrocarbon storage for many years in South Texas and Southern Louisiana. Two large caverns located approximately 35 miles north of the proposed BPT terminal location have been determined to be ideal candidates for immediate storage. These existing caverns, rated for natural gas storage, are located at Sulphur Mines, Louisiana. With minor modifications the caverns can be upgraded and ready to receive large quantities of gasified LNG from the BPT terminal.

Filename: 41653R01

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Document Title:

The United States Department of Energy National Energy Technology Laboratory Report II: “Conceptual Design of a Salt Cavern Based LNG Terminal”

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24 April 2003 Doc # & Version:

Doc 06 r1.0

Page 5 of 13

A visit to the Cameron Chamber of commerce and local courthouse yielded several very detailed maps indicating that an area west of the river, and at the mouth of the river just past the channel entrance could provide an ideal location for the marine facility, high pressure LNG pumps, and BPT exchangers (see Attachment I). An investigation of the site revealed that the land was marshy, uninhabited, and fairly remote. The Sabine National Wildlife Area lies well to the north of the proposed location. While no natural harbor exists along the Calcasieu River capable of berthing a large ocean going vessel, there appears to be ample space to dredge a slip on the western bank, and expand a small area just inside the mouth of the river. To facilitate LNG tanker maneuvering a turning basin will also have to be created at the mouth of the river (Attachment II – Plan View – Onshore LNG Terminal). The turning basin located at the mouth of the river offers no additional restrictions to navigation or vessel traffic. The USCG requires that all vessels in the vicinity of an LNG tanker entering a navigable waterway observe a Restricted Navigational Area (RNA). The RNA is defined as a clear space two miles ahead and one mile behind the LNG vessel until it is safely berthed. The turning basin at the mouth of the river will actually decrease traffic delays, as the LNG tanker will be quickly docked and off the river almost immediately after entering the river channel. Attachment II indicates the location of the proposed slip and turning basin. Also identified in Attachment II are: 1. 2. 3. 4. 5. 6. 7. 8. 9.

The loading and transfer arms Surge cylinder LNG pump house Vapor generator (required for forced vaporization) Water warmant intake and pumping structure Water warmant outfall structure Bishop Process Heat Exchangers Office, control room, and machine shop Power generation station

All components in the Plan View are drawn to scale and the dock reflects the capability of the BPT terminal to accept LNG carriers up to 250,000 m3. Although tankers of this size may never be built, the BPT LNG terminal with its massive sendout capability would be a likely offloading destination for LNG carriers of this size. The gasified LNG discharged from the terminal via the proposed 42” diameter high pressure pipeline is clearly marked. The pipeline connects the marine receiving terminal to the salt cavern storage facility located 35 miles away at Sulphur, Louisiana. The BPT LNG process does not require that LNG storage be located at or near the marine terminal, a major siting and security advantage. Filename: 41653R01

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Document Title:

2.1.

The United States Department of Energy National Energy Technology Laboratory Report II: “Conceptual Design of a Salt Cavern Based LNG Terminal”

Date of Issue:

24 April 2003 Doc # & Version:

Doc 06 r1.0

Page 6 of 13

BPT LNG Terminal - Process Flow Diagram

A Process Flow Diagram (PFD) of the BPT LNG terminal is illustrated in Attachment III. Although the mechanical elements differ between the BPT onshore and offshore terminal, the same basic process principles apply. Much of the machinery required to receive, regasify, and sendout out LNG to salt storage is identical. Therefore, the PFD depicted in Attachment III will be conceptually applicable to both terminals. Referencing Attachment III, the LNG vessel arrives and is secured at the berth. The four High Pressure Pumps (G-1 through G-4) housed in Pump Reservoir (C-2) are kept cold via recirculation of LNG with the Standby Mode Circulating Pump (G5) discharging into the LNG unloading line, through the surge vessel, and returning to the High Pressure Pump Reservoir(C-1). Recirculating LNG is allowed to flood the pump and motor housing and reenter the suction side of Circulating Pump G5. The vapor generated by the recirculation process is reliquefied in a Reliquefaction Packaged Compressor Unit K-2. Just prior to discharge, one pump from a single 4-pack, is placed in the recirculation mode with its discharge valve to the BPT exchanger cracked. The loading and vapor arms are connected and the LNG tanker begins to discharge its cargo. The LNG from the ship’s cargo pumps, pressurized at about 45 to 60 psig, begins to fill the surge vessel. The suction and discharge valves from the 4-pack are opened in increasing fashion to accommodate increasing volumes of LNG received from the ship’s cargo pumps until an equilibrium is achieved. As the ship brings more and more cargo pumps online, the 4-packs are started accordingly until full pumping rates are achieved. During the full rate pumping mode, all LNG is circulated through the Bishop Process Heat Exchangers (BPT) shown in the drawing as E-1 through E-4. Warming water is provided from a source with pump G6. The exchangers are designed with two separate inlets that circulate the warming water in opposite directions and provide a way to “refresh” the heat transfer capability. Multiple circulation modes ensure that the proper heat transfer takes place even with colder warmant temperatures. After leaving the exchanger, the regasified LNG now in the dense phase (for a detailed discussion, reference Subtask 1.3), passes through the 42” diameter pipeline and into the salt cavern storage facility. Boil Off Gas (BOG), is required to fill the ships tanks during discharge, and must be returned to the ship at the equivalent unloading rate. BOG is usually supplied via vapor generated by agitation in the LNG storage tanks during unloading. While discharging at the BPT LNG terminal, a reducing station supplied from the outlet of the BPT exchanger, and a blower (K-3) will provide the prescribed amount of vapor. Rate down and return to standby mode is accomplished by reversing the above procedure.

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2.2.

Date of Issue:

The United States Department of Energy National Energy Technology Laboratory

24 April 2003

Report II: “Conceptual Design of a Salt Cavern Based LNG Terminal”

Doc # & Version:

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List of Critical Machinery

Liberty LNG Terminal to Existing Salt Cavern Storage Description UPGRADES TO EXISTING STORAGE CAVERNS (Sulphur Mines, La) PROCESS VESSELS Recondenser, 9'ID x 45', 304 SS BOG Compressor Knock Out Drum 35 m3 HP Fuel Gas Knock Out Drum, 3 m3 HP Flare Knock Out Drum, 50 m3 Service Water Storage Tank, 20 m3 Diesel Storage Tank, 50 m3 Foam Tank, 4 m3 Surge Vessels VAPORIZERS

Submerged Combustion Vap., 205 mmcfd/433 m3/hr CPP Shell and Tube 150 mmcfd/317 m3/hr Bishop Process 128 mmcfd/270 m3/hr HEAT EXCHANGERS Standby glycol/fuel gas heater 127 kW HP knockout drum heater 20 kW Gaseous N2 Vaporizer 35 kW Gaseous N2 Vaporizer (Spare) 35 kW Liquid N2 Pressurization vaporizer 35 kW Liquid N2 Vaporizer 35 kW Waste Heat recovery from turbo-generator exhaust PUMPS

High Pressure sendout pump, 2,200 psi @ 270 m3/hr Process Area Sump Pump, 10 hp, 5 m3/hr Service Water Pump, 5 hp, 57 m3/hr Firewater Pumps COMPRESSORS

BOG compressor, 0.5 MMSCFD Ship Vapor Return Blower Ship Unloading Compressor SEAWATER INTAKE/OUTFALL (Incl Electrochlorination)

Seawater pump (warmant), 3150 m3/hr Electrochlorination Unit, 19,000 m3/hr

Seawater Intake Structure (19,000 m3/hr each) Seawater Outfall Structure (19,000 m3/hr each) Filename: 41653R01

Customer:

Document Title:

The United States Department of Energy National Energy Technology Laboratory Report II: “Conceptual Design of a Salt Cavern Based LNG Terminal”

Date of Issue:

24 April 2003 Doc # & Version:

Doc 06 r1.0

Page 8 of 13

Seawater Intake Screens (20,000 m3/hr each) Seawater Rotary Screens (20,000 m3/hr each) UTILITIES HP Flare, 415,000 kg/hr Electrical Switchgear & Power Distrib (5% of FC) Emergency Generator - Diesel Driven, 500 kW

Lighting Generator - Diesel Driven, 750 kW GE LM 2500+ with chiller and DLE low emissions package Instrument air compressor and drier, 100 scfm N2 Dewar for Terminal, Vac. insul. tank, 42 m3 Firewater Protection System (Foam Sys, dry powder, tanks) MARINE FACILITIES - JETTY

Platforms and walkways Cryogenic Piping (I/E, piping w/ insulation) Berth (Mooring, Breasting Dolphins) Dredging MARINE FACILITIES - UNLOADING Unloading Arms NAVIGATIONAL AIDS (lighting and buoys) BUILDINGS Administration Office/Control Center Building for Sendout Pumps Warehouse/Maintenance Building, 10,000 sf SITE PREPARATION BULKS Piping (exclud. trestle) Piling Insulation and Paint Instrumentation and metering skids REAL ESTATE PIPELINE TO SULPHUR MINES TIE IN TO MAJOR FOUR PIPELINES

2.3.

Estimated Costs and Revenues

There are three major elements contributing to the overall total installed cost (TIC) of the LNG onshore terminal, the LNG terminal at the mouth of the Calcasieu River, the upgrades and pipeline interconnects required for the existing salt cavern facilities, and the 35 mile pipeline required to connect the offloading terminal to the storage caverns. The cost estimates for the financial model (Attachment IV) were developed using a factored cost estimating program specific to the industry. Budget estimates for upgrading the existing salt cavern facilities are based on actual operating experience and direct quotations. Pipeline estimates were sourced from the contractors. Filename: 41653R01

Customer:

Document Title:

The United States Department of Energy National Energy Technology Laboratory Report II: “Conceptual Design of a Salt Cavern Based LNG Terminal”

Date of Issue:

24 April 2003 Doc # & Version:

Doc 06 r1.0

Page 9 of 13

The financial model applied is based on a long-established standard model for gas storage. Necessary modifications were made to reflect the key economic and financial aspects of the onshore LNG Terminal modeled after the actual project mentioned throughout the above sections, especially in the area of terminal energy use fees and actual terminal energy use requirements. The major elements of the terminal TIC and O & M budget are included on the second and third page of Attachment IV. The major elements of the economic/financial model and its results are shown on the “Summary” page, e.g. Attachment IV pg. 1. Most of the items on the “Summary Facility Assumptions” page are self explanatory. Notable items, parameters, and assumptions for the Onshore LNG terminal are described below. The facility sizing basis is shown in the section of the “Summary” page labeled “Facility Basis” and “LNG Terminal Project Metrics.” The reference assumption is 225 cargos per year and this corresponds to 1.7 Bcf per day average daily import and grid dispatch quantity. Note that 16 Bcf figure for “Storage Working Gas Volume” is an off-line technical result regarding total storage capacity of the salt caverns and the economic model makes no assumptions regarding the amount of storage capacity required for the LNG terminal operations. “Pricing” is the next section of the “Summary” page. The “Throughput Fee” is assumed as a $ amount per mmBtu. This assumption can be varied to determine the IRR associated with the assumed fee to satisfy a certain IRR target or “hurdle rate.” The “Other Revenue” line allows for other revenue that might be generated as a percentage of LNG throughput. In fact, the storage terminal with multiple connections may be able to realize fees from services in addition to LNG import terminal operations (such as gas storage or hub services). These fees may or may not relate to the percentage of revenue from LNG terminal throughput fees. For a reference case focused on only LNG terminal operations, both of the “other revenue” assumptions have been set to zero. The “Pricing” section also includes pricing parameters for the “Terminal Energy Use Charge” expressed as a percentage of throughput retained by the terminal as a fuel charge. In the financial projections, this amount is inflated with the general inflation rate and the amount is modeled as a Henry Hub index price. The “Other Assumptions” section of the “Summary” page includes a number of important parameters that affect the economics/financial results. The section labeled “Others” is reflects fees for “Technology Rights” and is intentionally left blank to better compare the onshore and offshore options. The next major section of the “Summary Facility Assumptions” block of the “Summary” page shows the capital cost for various major components of the terminal. These are largely self-explanatory. The “Project Metrics” summarizes some commonly applied quantity references for the LNG terminal business. The “Tax Rates” section shows the assumptions for tax rates applicable for a Louisiana project. The calculation of “terminal value” for cash flow purposes assumes sale of the facility on an EBITDA multiple basis with the resulting proceeds realizing capital gains treatment for federal tax purposes and ordinary rates for state tax purposes. The “Depreciation” section allows different assumptions to be made that affect primarily the after-tax cash flows to the ownership. In order to provide for a more conservative (i.e. higher required fee or reduced IRR depiction) assessment, the reference assumption is for straight-line depreciation over 20 years. “Financial Assumptions” are shown in the block on the upper right hand side. A 50-50 debt equity structure is assumed with debt costs at prime plus 2% which corresponds to 6.75% for a reference case. The time period for repaying debt has a strong effect on equity cash flows, debt service coverages, and equity returns. Given the long term nature of the related investments for LNG production and transport, a 20 year amortization period is assumed. The “Financial Results” block shows model outputs generally from the cash flow calculation. The cost of capital is a straightforward calculation based on the input assumptions for costs and amounts of debt and equity. The “Project Economics” section reflect results for the project without any debt. This is essentially an “all equity” approach to project NPV and IRR. Estimated EBTIDA amounts are expressed in thousands of Filename: 41653R01

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The United States Department of Energy National Energy Technology Laboratory Report II: “Conceptual Design of a Salt Cavern Based LNG Terminal”

Date of Issue:

24 April 2003 Doc # & Version:

Doc 06 r1.0

Page 10 of 13

dollars per year. Equity returns as NPV and IRR are shown on an after tax basis for cash-on-cash expected flows. Minimum debt service coverages are demonstrated on a pre-tax basis as shown. Based on a throughput fee of $0.096 mmBtu, the conceptual land based terminal in years one through five averaged an EBITDA of $45,129,000 USD based on a through-put of 225 cargoes per year. On a 16.4% after tax equity IRR the projected equity return was $21,377,000 USD. The same financial model is used for the offshore terminal with modifications to Project Budget and O & M expenses only. 3. THE LNG OFFSHORE TERMINAL 3.1.

Conceptual Layout

The offshore LNG terminal using the BPT exchangers and salt caverns as storage is pictured in Attachment V. The Process Flow Diagram varies little from the onshore terminal, therefore more attention will be focused on offshore layout. The illustration clearly shows the swing arm mechanism “Big Sweep” designed to safely berth the LNG carrier and an adjacent platform with the major process machinery. The mooring platform houses the high pressure LNG pumps that pressurize the LNG to 2,200 psig. The pressurized liquid is routed to the regasification platform via a subsea pipeline rated for cryogenic service. LNG passes through the BPT exchanger and moves directly into the offshore gas gathering system, or to the salt caverns for storage. The following explanation is excerpted from section 1.2 for the reader’s convenience. The ‘Big Sweep’ concept consists of three basic elements, see figure 3.1-1 on the following page. • • •

A jacket structure with turntable, anchored to the seabed A submerged rigid arm, hinged at one end to the jacket turntable and terminating at its other end with a buoyant column, and The LNG loading and transfer structure, located on top of the buoyant column.

To allow the vessel and arm to passively ‘weathervane’ into the most favourable direction with respect to the environment, the turntable is connected to the jacket structure by means of a bearing. This allows the turntable to rotate 360° with respect to the jacket. The turntable supports the rigid arm hinges, the cryogenic fluid swivels and the hawser attachment point. The overall length of the rigid arm is such that the buoyant column is positioned nominally near the midship cargo manifold of the LNG carrier. By adjusting the length of the mooring hawser the carrier’s cargo manifold can be lined up to the offloading station for vessel sizes ranging from large to very large gas carriers. The buoyant hull is equipped with a thruster system to swing the arm in a safe position during approach of the vessel and in-line with the vessel in the operational mode. A water ballast tank allows draft adjustment of the loading arm to match tanker size and / or drafts. The standard fluid transfer system consists essentially of 3 Pipe-in-Pipe (PIP) lines. Two lines are dedicated to LNG; either in full flow mode or re-circulation mode. The third line is dedicated for vapour return. The flow paths cross the weathervaning and pitch hinges between the jacket and the rigid arm. This is achieved with swivels and full metal jumpers which can be easily inspected and serviced. The loading arm is normally trailing the jacket but can be temporarily ‘parked’ away from the LNG carrier line of approach, with its own propulsion. In this position the entire loading arm assembly cannot be damaged by a failed mooring approach of the export carrier tanker. Note that offshore tanker mooring to SPM systems is standard marine practice and that a failed approach run very rarely happens. Should the carrier ‘brush’ against the terminal, this will be a ‘low energy’ collision which can be accommodated by the cushioning fender system. Filename: 41653R01

The United States Department of Energy National Energy Technology Laboratory

Customer:

Document Title:

Report II: “Conceptual Design of a Salt Cavern Based LNG Terminal”

Date of Issue:

24 April 2003 Doc # & Version:

Doc 06 r1.0

Page 11 of 13

The LNG carrier moors in tandem with the turntable and once it has secured itself safely and the overall alignment is stable, the loading arm will be deployed from its parked position toward the vessel’s manifold. The hose deployment and loading operation may now be initiated. After completion of the transfer operations all of the steps discussed above are done in reverse order. fig. 3.1-1

Shallow Water depth Terminal. Developed from the ‘Big Sweep’ system, this unit shown in fig. 3.1-2 is designed to operate in water depths below 40 m, It allows direct offshore-to-shore transfer of LNG, at rates up to 10,000 m3/hr from non-dedicated vessels. Motion characteristics are such that offloading can proceed up to significant wave heights of 3 m, depending on the water depth, which may be as little as 15 meters. With dynamic positioning (DP) capability the unit would track the movement of the LNG carrier manifold when loading or unloading LNG. DP would also allow the unit to move out of the way when the LNG carrier is mooring itself to the turntable on the jacket, thereby avoiding marine hazards. For extreme survival conditions e.g. the Gulf of Mexico, the free-end of the unit is waterballasted and set temporarily on the seabed.

Filename: 41653R01

Customer:

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The United States Department of Energy National Energy Technology Laboratory Report II: “Conceptual Design of a Salt Cavern Based LNG Terminal”

Date of Issue:

24 April 2003 Doc # & Version:

Doc 06 r1.0

Page 12 of 13

fig. 3.1 -2

Re-gasification equipment may be located on the unit for applications without LNG storage e.g. where gas is stored in salt caverns or delivered directly to the shore gas grid. Attachment VI is a plan view if the facility to scale. The platforms are approximately 1800 meters apart to allow for ample maneuvering distance. Although the plan view indicates that four caverns will be used for storage, the number and size of the caverns are for the most part subject to customer requirements as most salt formations can accommodate any number of caverns. Attachment VII has been included to better illustrate the major components of the offshore LNG terminal.

3.2.

Offshore Terminal - Estimated Cost and Revenue

There are three major elements contributing to the overall total installed cost (TIC) of the LNG offshore terminal, (1) platforms and weathervaning mooring facilities, (2) the cryogenic pipeline required to connect the mooring facility to the cavern platform, and (3) the newly designed solution mined salt storage caverns. The cost estimates for the financial model (Attachment VIII) were developed using a factored cost estimating program specific to the industry. Budget estimates for the offshore mooring facilities are based on actual operating experience and direct quotations. Cryogenic pipeline estimates were sourced from the contractors. The financial model applied is based on a long-established standard model for gas storage. Necessary modifications were made to reflect the key economic and financial aspects of the offshore LNG Terminal based on the designers best estimates, especially in the area of terminal energy use fees and actual terminal energy use requirements. The major elements of the terminal TIC and O & M budget are included on the second and third page of Attachment VIII. The major elements of the economic/financial model and its results are shown on the “Summary” page, e.g. Attachment VIII pg. 1. Most of the items on the “Summary Facility Assumptions” page are self explanatory. Please refer to section 2.3 of this report for additional details of notable items, parameters, and assumptions for the Offshore LNG terminal. The “Financial Results” block shows model outputs generally from the cash flow calculation. The cost of capital is a straightforward calculation based on the input assumptions for costs and amounts of debt and equity. The Filename: 41653R01

Customer:

Document Title:

The United States Department of Energy National Energy Technology Laboratory Report II: “Conceptual Design of a Salt Cavern Based LNG Terminal”

Date of Issue:

24 April 2003 Doc # & Version:

Doc 06 r1.0

Page 13 of 13

“Project Economics” section reflects results for the project without any debt. This is essentially an “all equity” approach to project NPV and IRR. Estimated EBTIDA amounts are expressed in thousands of dollars per year. Equity returns as NPV and IRR are shown on an after tax basis for cash-on-cash expected flows. Minimum debt service coverages are shown on a pre-tax basis as shown. Based on a throughput fee of $0.095 mmBtu, the conceptual offshore terminal in years one through five averaged an EBITDA of $42,698,000 USD based on a through-put of 230 cargoes per year. On a 16.4% after tax equity IRR the projected equity return was $20,493,000 USD.

Filename: 41653R01

LLC

Liberty Terminal LNG receiving Facility

D. B. Scherz Site View

DOE AWARD: DE-FC26-02NT41653

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Regasified LNG to Sulfur Mines 42" pipeline 2,200 psig

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Lot 26 8

Turning Basin Diameter 460 x D 14 m

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LEGEND 2

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1. Loading Dock and LNG Transfer Arms

4m 323 x 5 ip h S LNG 0 m3 250, 00

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63 m 3 m x 1 ed 6 5 p li S uir Second l dredging req a n additio

Expanded Turning Basin (required for second slip expansion) B

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2. Surge Cylinder 3a LNG Pump House: 7 ea. 4-packs; 7560 m3/hr; 2,200 psig 3b Vapor Generator for Ships tanks (in pump house)

4

4. Warmant Outfall Structure

Battery Limits Battery Limits 1020 m x 740 m 1020 m x 740 m

5. Warmant Water Pumps and Intake Structure 6. Bishop Process Heat Exchangers: 28 ea. 338 m long 7. Office, Control Room, and Machine Shop

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8. Power Generation

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90.0 m. 150.0 m.

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C-1 Surge Vessel 4 x volume of pump reservoir (C-2) 525 m3

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K-1 Compressor

C-2 Pump Reservoir

Boil Off Gas Reciprocating Elect. Driven, used during cool down and Idle plant only.

One reservoir holds 4 LNG pumps. Each “4 Pack” pumps 1080 m3/hr. Base case of 28 pumps or seven “4 Packs” will move 7560 m3/hr.

K-2 Reliquifaction

K-3 Vapor Return Blower

Reliquifier to keep pumps and process vessels cool during idle plant.

To LNG Carrier

5 GT-1&2 GE 2500+ Gas Turbine Generators 66,000 KVA

4

E-5 Inlet Air Chiller

G-1 through G-4 LNG High Pressure Pumps

G-5 LNG Recirculation Pump

To Gas Turbine Generators

2660 hp Suc: 65 psi Dis: 2200 psi 270 m3/hr -256 F/-160 C

105 hp Suc: 3 psi Dis: 25 psi 30 m3/hr -256 F/-160 C

3

E-1 through E-4 Heat Exchangers

RV-1 Reducing Valve To Vapor Return

co-axial flow pipe in pipe -256 F to +40 F (assumed)

2200 psig to 15 psig

2

RV-2 Reducing Valve Fuel Gas to Gas Turbine Gen Sets

G-6 Primary Sea Water Circ Pump

C-3 Salt Caverns

V-1 Cavern inlet valve

16 Bcf includes 6 caverns

100 psi delta p 1000 hp 3,292 gpm

2200 psig to 350 psig

1 PRV-3 Cavern outlet valve pressure reducing valve

H

G

G 1200 psig

Vapor Return PIC PRV-3

LNG Discharge

K-3

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F 35 mile Pipeline from Marine Terminal to Sulfur Mines

K-2

2200 psig PRV-1

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Note 3

V-1

K-1

Notes 1. Items within box sketched with dotted line are fabricated in one modular unit and designated a “4-pack”.

E-1 V-14

D G-1

2. This drawing illustrates the layout for one LNG high pressure pumping unit only. The base case terminal employs seven “4-packs”. Each “4-pack” consists of a reservoir and four integral pumps. The terminal can be sized to fit the client’s requirements by adding or subtracting “4 packs”.

E-2

V-15

C-3 G-2 LI

G-5

C

Note 3

3. Denotes warmant water inlet structure and strainers.

E-3

V-16

G-3

C

4. Denotes warmant water outfall structure. 5. Cavern metering and dehydration not shown in this PFD. Vessel CTMS to be used for measurement during unloading.

C-2 E-4

350 psig to Fuel Gas System

V-17

G-4

B

D

See note 2 Recirculation Line - Unloading Mode

P-65

B

E-5

Note 4 LLC

DOE AWARD: DE-FC26-02NT41653

&

Recirculation Line - Stand-by Mode G-5

A

D. B. Scherz

GT-1 & 2

Conceptual PFD

8

7

6

5

4

3

SIZE

Scale

No.

DWG NO

REV

Atttachment

DOC 06 Attach III

00

see legend

2

3/30/03

1 OF 1

Sheet

1

A

LIBERTY LNG TERMINAL PROFORMA ECONOMICS Doc 06 Attachment IV pg 1 SUMMARY FACILITY ASSUMPTIONS Facility Basis - Firm Service Cargos per Year LNG Discharge per Ship, cubic meters LNG LNG Btu content, Btu/scf Storage Working Gas Volume, Bcf Storage Base Gas Volume, Bcf

Pricing Throughput Fee, $/MmBtu Other Revenue - % of Terminal Throughput Rev. Terminal Energy Use Charge, % of throughput Assumed Henry Hub Index for initial year Gas Storage Net Revenue Realized $MM/year Other Assumptions Base Gas Price (Delivered), $/Mcf Base Gas Source ("Lease" or "Buy") Total Operations Cost, $M/Year - Labor & Maintenance, $M/Yr - Electrical Demand Charge, $M/Yr Management Overhead, $M/Year Property Taxes (assumed amount), $M/Yr Storage Site Lease Fee, $M/yr % Revenue Stream to Inflation Protect, %/yr General Inflation Rate Inflation applied to certain annual costs, %/yr Energy Use for Terminal ops., % of throughput Full storage cavern compression charge rate % of throughput requiring compression at cavern Project & Technology Rights Running Royalty, as % of Henry Hub index Project & License Upfront Payment, $MM

225 138,000 1067 16.00 7.30

0.096 0.0% 0.00% $3.50 $0.0

3.50 lease 4,544 4,344 200 360 4,000 500 100% 3.0% 1.5% 0.35% 1.25% 5%

Facility Costs, $ Marine Port Facilities LNG Process & HP Pipeline Terminal Utility System Storage Surface Facility Storage Construction Header Pipeline Engineering & Const. Mgmt. Project Acquisition & Tech. Rights Owner Costs, Permits, Misc. Financing Fees Contingency Total Facility Cost

FINANCIAL ASSUMPTIONS 56,733,600 136,310,776 28,188,700 17,363,650 18,358,100 14,397,250 14,925,225 1,920,000 7,361,958 16,281,125 43,784,595 355,624,979

LNG Terminal Project Metrics 94% Load Factor (based on 240 cargos/yr max) Reference Annual throughput, mcf/yr 612,077,267 Annual LNG Offloaded, BCF/yr 612 Reference throughput, million mmBtu/yr 653,086,444 Daily equivalent amount (mcf/day) 1,700,215 Tax Rates Federal, %/YR 35.0% State, %/YR 4.50% Blended Rate, %/Yr. 37.93% Property, %/YR, initial year/capital cost 1.12% Capital Gain Rate for Terminal Value 20% Depreciation Depreciation (Straight-Line or Accel) Straight-Line Depreciable Life, Years 20 Project Life, Years 20

0.00% based on mmBtu throughput 0

Financial Structure Sr. Debt Percent of Capital Jr. Debt Percent of Capital Equity Percent of Capital Senior Debt Term Junior Debt Term Base Gas Lease Carrying Cost, %/YR

% Capital 50.0% 0.0% 50.0% 20 5 6.75%

FINANCIAL RESULTS Cost of Capital Pretax WACC WACC Equity Return (assumed from above)

10.88% 9.60% 15.0%

Project Economics Project NPV@Pretax WACC, $M Project Pretax IRR NPV @ WACC (tax-effected), $M Project IRR (tax-effected)

147,579 15.1% 93,835 12.1%

Yr. 1 EBITDA $M/year Avg. EBITDA, Yrs 1-5, $M/year

$42,139 $45,129

Equity Returns, AFTER-Tax Equity NPV@ Assumed Equity Return, $M

Equity IRR (calculated) Debt Coverage Minimum EBITDA/Interest Coverage Minimum EBITDA/Debt Service

21,377 16.4% Pre-tax

3.5 2.6

Rate 6.75% 0.0% 15.0%

LIBERTY LNG TERMINAL PROFORMA ECONOMICS Doc 06 Attachment IV pg 2 Description

Units

Per Unit, $

Quantity

$

Marine Port Facilities Jetty Unloading Arms Dredging Navigational Aids Buildings Site Preparation Bulks Subtotal Marine & Port Facilities

Each Each Cubic meter Each Lot Lot Lot

20,919,000 542,750 6.00 108,540 2,060,000 3,774,000 17,933,000

1 4 1,555,650 5 1 1 1

20,919,000 2,171,000 9,333,900 542,700 2,060,000 3,774,000 17,933,000 56,733,600

LNG Process & HP Pipeline Vaporizers (Bishop) Process Equipment LNG Pumps Compressors Seawater System w/ heat recovery High Pressure Pipeline to Storage Subtotal Process & Pipeline

Each Lot Lot Lot Lot Mile

689,992 727,000 691,750 5,065,000 23,930,000 1,940,000

28 1 28 1 1 35

19,319,776 727,000 19,369,000 5,065,000 23,930,000 67,900,000 136,310,776

Description

Units

Engineering & Const. Mgmt. Marine Port, % Facility Cost LNG Vaporization, % facility Cost Terminal Utility, % Facility Cost Pipelines,% P/L Cost Surface Facilities, % Surface Cost Storage Development, % Storage Cost Subtotal Engineering

Percent Percent Percent Percent Percent Percent

Owner Start-Up Costs Labor Training Subtotal Start-up Costs

Man-hour Lot

Property Rights Terminal Facilities Land Acquisition Project Acquisition & License cost

Acre Lot

Per Unit, $

5% 10% 5% 3% 5% 5%

Quantity

$

47,399,700 68,410,776 28,188,700 82,297,250 18,358,100 18,358,100

50 50,000

4,000 6

200,000 300,000 500,000

640 0

3,000 1

1,920,000 0

Subtotal Property Rights Terminal Utility System Power Generation - LM2500+ Other Generation Firewater & Other Pumps Flare Miscellaneous Subtotal Utility Facility Storage Surface Facility Compression Dehydration Pressure Vessels Site Work Buildings In-Plant Piping Electrical/Instrumentation Substation Miscellaneous Labor Plus Profit Subtotal Surface Facility Storage Construction Well Drilling Replacement Brine Wells Additional Gas Wells Rework Existing Wells Miscellaneous Leaching Plant Materials & Labor Electricity for Leaching/Debrining Subtotal Storage Construction Header Pipeline to North No. Header Pipeline ROWs Northern header - 36" Tie-Ins M&R Stations plus tie-ins Borings Water Crossing (Drilling) Miscellaneous Subtotal Pipeline

Each Lot Lot Lot Lot

HP Lot Lot Lot Lot Lot Lot Lot Lot Lot

Per Well Per Well Per Well Lot Lot BCF

Rods Miles Each Each Each Each Lot

9,368,500 914,000 967,700 818,000 6,752,000

355 1,000,000 430,000 1,146,000 449,000 2,099,000 1,578,000 1,000,000 673,650 5213000

3,175,500 4,700,000 607,000 428,100 600,000 50,000

350 633,360 24,000 750,000 8,300 8,300 328,350

2 1 1 1 1

5,000 3 1 1 1 1 1 1 1 1

2 2 2 1 1 7.3

4,000.0 12.5 6 6 9 4 1

18,737,000 914,000 967,700 818,000 6,752,000 28,188,700

1,775,000 3,000,000 430,000 1,146,000 449,000 2,099,000 1,578,000 1,000,000 673,650 5,213,000 17,363,650

6,351,000 9,400,000 1,214,000 428,100 600,000 365,000 18,358,100

1,400,000 7,917,000 144,000 4,500,000 74,700 33,200 328,350 14,397,250

Permits Preliminary Engineering Environmental Study FERC/State/Other Permits Subtotal Permits Insurance Title Liability

1,920,000

Man-hour Lot Lot

100 1,000,000 1,000,000

4,000 1 1

400,000 1,000,000 1,000,000 2,400,000

300,000 500,000

1 1

300,000 500,000 800,000

1,000,000 361,958 1,000,000 1,000,000 300,000

1 1 1 1 1

1,000,000 361,958 1,000,000 1,000,000 300,000 3,661,958

Percent of Project Percent of Project Percent of Construction Lot

0.0% 0.0% 6.0% 0

291,897,301 291,897,301 271,352,076 1

0 0 16,281,125 0 16,281,125

Percent of Project

15.0%

291,897,301

43,784,595 43,784,595

Lot Lot Subtotal Insurance

Owner Costs Spare Parts/O&M Lot Working Capital, months of O&M Monthly O&M Expenses Development Overhead Lot Legal Lot Project Marketing Lot Subtotal Owner Costs Financing Fees Investment Banker Fee Lender Commitment Fee Interest During Construction Third Party Review Subtotal Financing Fees Contingency Contingency Subtotal Contingency

Total Project . Depreciable . Nondepreciable Budget excluding contingency

2,369,985 6,841,078 1,409,435 2,468,918 917,905 917,905 14,925,225

355,624,979 355,624,979 0 311,840,384

LIBERTY LNG TERMINAL PROFORMA ECONOMICS Doc 06 Attachment IV pg 3 Operations & Maintenance Expenses - Year 1 Units

Per Unit

Quantity

Total Cost

Each Each Each % of Payroll

100,000 40,000 45,000 35%

3 2 14 1,010,000

300,000 80,000 630,000 353,500 1,363,500

Lot Lot Lot Lot

240,000 600,000 120,000 10,000

1 1 1 1

240,000 600,000 120,000 10,000 970,000

Material & Supplies Spare Parts Lot Chemicals Lot Plant Supplies Lot Subtotal Material & Supplies

160,000 100,000 140,000

1 1 1

160,000 100,000 260,000 260,000

200,000 20,000 1,300,000 40,000 80,000 10,000 100,000

1 1 1 1 1 1 1

200,000 20,000 1,300,000 40,000 80,000 10,000 100,000 1,750,000

Description Labor Managers Administrative Field Operators & Technicians Benefits Subtotal Labor Subcontractor Services Contract Repairs Contract Services Equipment Rental Computer Services Subtotal Subcontractor Services

Direct Operating & Maintenance Expenses Major item replacement Recruiting & Training Insurance Auto & Truck Rental Tools & Equipment Travel Miscellaneous Subtotal Direct Opereration & Misc. Exp. Project O&M Total

Lot Lot Lot Lot Lot Lot Lot

4,343,500

Offshore LNG Terminal Conceptual Drawing Doc 06 Attachment V DE-FC26-02NT4165

Doc 06 Attachment VI DE-FC26-02NT41653

©Bluewater Offshore Production Systems (U.S.A.), Inc.

Process Flow Diagram Offshore LNG Terminal Doc 06 Attachment VII

BLUEWATER LNG TERMINAL PROJECT SUMMARY Doc 06 Attachment VIII pg 1 SUMMARY FACILITY ASSUMPTIONS Facility Basis - Firm Service Cargos per Year LNG Discharge per Ship, cubic meters LNG LNG Btu content, Btu/scf Storage Working Gas Volume, Bcf Storage Base Gas Volume, Bcf

Pricing Throughput Fee, $/MmBtu Other Revenue - % of Terminal Throughput Rev. Terminal Energy Use Charge, % of throughput Assumed Henry Hub Index for initial year Gas Storage Net Revenue Realized $MM/year Other Assumptions Base Gas Price (Delivered), $/Mcf Base Gas Source ("Lease" or "Buy") Total Operations Cost, $M/Year - Labor & Maintenance, $M/Yr - Electrical Demand Charge, $M/Yr Management Overhead, $M/Year Property Taxes (assumed amount), $M/Yr Storage Site Lease Fee, $M/yr % Revenue Stream to Inflation Protect, %/yr General Inflation Rate Inflation applied to certain annual costs, %/yr Energy Use for Terminal ops., % of throughput Full storage cavern compression charge rate % of throughput requiring compression at cavern Project & Technology Rights Running Royalty, as % of Henry Hub index Project & License Upfront Payment, $MM

230 138,000 1067 16.00 7.30

0.095 0.0% 0.00% $3.50 $0.0

3.50 lease 7,350 7,150 200 360 4,000 500 100% 3.0% 1.5% 0.35% 1.25% 5%

Facility Costs, $ Marine Port Facilities LNG Process & HP Pipeline Terminal Utility System Storage Surface Facility Storage Construction Header Pipeline Engineering & Const. Mgmt. Project Acquisition & Tech. Rights Owner Costs, Permits, Misc. Financing Fees Contingency Total Facility Cost

FINANCIAL ASSUMPTIONS 81,942,700 57,809,800 28,188,700 25,055,650 43,996,100 18,698,900 15,433,327 10,000 8,595,792 15,341,511 41,375,277 336,447,756

LNG Terminal Project Metrics 96% Load Factor (based on 240 cargos/yr max) Reference Annual throughput, mcf/yr 625,678,984 Annual LNG Offloaded, BCF/yr 626 Reference throughput, million mmBtu/yr 667,599,476 Daily equivalent amount (mcf/day) 1,737,997 Tax Rates Federal, %/YR 35.0% State, %/YR 4.50% Blended Rate, %/Yr. 37.93% Property, %/YR, initial year/capital cost 1.19% Capital Gain Rate for Terminal Value 20% Depreciation Depreciation (Straight-Line or Accel) Straight-Line Depreciable Life, Years 20 Project Life, Years 20

0.00% based on mmBtu throughput 0

Financial Structure Sr. Debt Percent of Capital Jr. Debt Percent of Capital Equity Percent of Capital Senior Debt Term Junior Debt Term Base Gas Lease Carrying Cost, %/YR

% Capital 50.0% 0.0% 50.0% 20 5 6.75%

FINANCIAL RESULTS Cost of Capital Pretax WACC WACC Equity Return (assumed from above)

10.88% 9.60% 15.0%

Project Economics Project NPV@Pretax WACC, $M Project Pretax IRR NPV @ WACC (tax-effected), $M Project IRR (tax-effected)

140,265 15.1% 89,365 12.1%

Yr. 1 EBITDA $M/year Avg. EBITDA, Yrs 1-5, $M/year

$39,849 $42,698

Equity Returns, AFTER-Tax Equity NPV@ Assumed Equity Return, $M

Equity IRR (calculated) Debt Coverage Minimum EBITDA/Interest Coverage Minimum EBITDA/Debt Service

20,493 16.4% Pre-tax

3.5 2.6

Rate 6.75% 0.0% 15.0%

BLUEWATER LNG TERMINAL PROJECT BUDGET Doc 06 Attachment VIII pg 2 Description

Units

Marine Port Facilities Big Sweep Rotating Arm Includes: platform, pipng, utilities, outfitting, jacket,& equipment Cryogenic Pipelines 1,800 meter Navigational Aids Offshore Installation Subtotal Marine & Port Facilities LNG Process & HP Pipeline Vaporizers (Bishop) Process Equipment LNG Pumps Compressors Seawater System w/ heat recovery High Pressure Pipeline to Storage Subtotal Process & Pipeline

Per Unit, $

Quantity

$

Each Each Each Each Each Lot Lot

70,000,000

1

3,200,000

2

108,540 5,000,000

5 1

Each Lot Lot Lot Lot Mile

717,100 727,000 691,750 5,065,000 930,000 1,940,000

28 1 28 1 1 6

70,000,000 0 0 6,400,000 0 542,700 5,000,000 81,942,700

20,078,800 727,000 19,369,000 5,065,000 930,000 11,640,000 57,809,800

Description

Units

Engineering & Const. Mgmt. Marine Offshore, % Facility Cost LNG Vaporization, % facility Cost Terminal Utility, % Facility Cost Pipelines,% P/L Cost Cavern Facilities, % Surface Cost Storage Development, % Storage Cost Subtotal Engineering

Percent Percent Percent Percent Percent Percent

Owner Start-Up Costs Labor Training Subtotal Start-up Costs

Man-hour Lot

Property Rights Terminal Facilities Land Acquisition Project Acquisition & License cost

Acre Lot

Per Unit, $

5% 10% 5% 3% 5% 5%

Quantity

$

81,942,700 46,169,800 28,188,700 30,338,900 43,996,100 43,996,100

50 50,000

4,000 6

200,000 300,000 500,000

10 0

1,000 1

10,000 0

Subtotal Property Rights Terminal Utility System Power Generation - LM2500+ Other Generation Firewater & Other Pumps Flare Miscellaneous Subtotal Utility Facility Storage Platform Facility Compression Dehydration Pressure Vessels Site Work Deck Structures Hex Bridge In-Plant Piping Electrical/Instrumentation Injection Platform Jacket Only Miscellaneous

Each Lot Lot Lot Lot

HP Lot Lot Lot Lot Lot Lot Lot Lot

9,368,500 914,000 967,700 818,000 6,752,000

355 1,000,000 430,000 500,000 5,000,000 2,099,000 1,578,000 10,000,000 673,650

2 1 1 1 1

5,000 3 1 1 1 1 1 1 1 1

Subtotal Surface Facility Cavern Construction Well Drilling Brine Wells Additional Wells Miscellaneous Facility and Site Prep Electricity for Leaching/Debrining Subtotal Storage Construction

Per Well Per Well

4,550,500 5,700,000

6 2

Lot Lot BCF

428,100 4,500,000 50,000

1 1 7.3

18,737,000 914,000 967,700 818,000 6,752,000 28,188,700

1,775,000 3,000,000 430,000 500,000 5,000,000 2,099,000 1,578,000 10,000,000 673,650 0 25,055,650

27,303,000 11,400,000 0 428,100 4,500,000 365,000 43,996,100

Permits Preliminary Engineering Environmental Study FERC/State/Other Permits Subtotal Permits Insurance Title Liability

10,000

Man-hour Lot Lot

100 1,000,000 2,000,000

4,000 1 1

400,000 1,000,000 2,000,000 3,400,000

300,000 500,000

1 1

300,000 500,000 800,000

1,000,000 595,792 1,000,000 1,000,000 300,000

1 1 1 1 1

1,000,000 595,792 1,000,000 1,000,000 300,000 3,895,792

Percent of Project Percent of Project Percent of Construction Lot

0.0% 0.0% 6.0% 0

275,835,177 275,835,177 255,691,850 1

0 0 15,341,511 0 15,341,511

Percent of Project

15.0%

275,835,177

41,375,277 41,375,277

Lot Lot Subtotal Insurance

Owner Costs Spare Parts/O&M Lot Working Capital, months of O&M Monthly O&M Expenses Development Overhead Lot Legal Lot Project Marketing Lot Subtotal Owner Costs Financing Fees Investment Banker Fee Lender Commitment Fee Interest During Construction Third Party Review Subtotal Financing Fees Contingency Contingency

4,097,135 4,616,980 1,409,435 910,167 2,199,805 2,199,805 15,433,327

Subtotal Contingency

Header Pipeline to Subsea Infrastructure Subsea Pipeline Tie-Ins M&R Stations plus tie-ins Borings Miscellaneous

Miles Each Each Each Lot

Subtotal Pipeline

633,360 24,000 750,000 8,300

20.0 3 6 9

1,385,000

1

0 12,667,200 72,000 4,500,000 74,700 0 1,385,000 18,698,900

Total Project . Depreciable . Nondepreciable Budget excluding contingency

336,447,756 336,447,756 0 295,072,480

BLUEWATER LNG TERMINAL OPERATIONS AND MAINTENANCE EXPENSES Doc 06 Attachment VIII pg 3 Operations & Maintenance Expenses - Year 1 Units

Per Unit

Quantity

Total Cost

Each Each Each % of Payroll

100,000 40,000 45,000 35%

6 4 18 1,570,000

600,000 160,000 810,000 549,500 2,119,500

Lot Lot Lot Lot

240,000 600,000 120,000 10,000

2 2 1 1

480,000 1,200,000 120,000 10,000 1,810,000

Material & Supplies Spare Parts Lot Chemicals Lot Plant Supplies Lot Subtotal Material & Supplies

160,000 100,000 140,000

4 1 1

640,000 100,000 740,000 740,000

200,000 50,000 1,300,000 500,000 80,000 250,000 100,000

1 1 1 1 1 1 1

200,000 50,000 1,300,000 500,000 80,000 250,000 100,000 2,480,000

Description Labor Managers Administrative Field Operators & Technicians Benefits Subtotal Labor Subcontractor Services Contract Repairs Contract Services Equipment Rental Computer Services Subtotal Subcontractor Services

Direct Operating & Maintenance Expenses Major item replacement Recruiting & Training Insurance Transport Rental Tools & Equipment Travel Miscellaneous Subtotal Direct Opereration & Misc. Exp. Project O&M Total

Lot Lot Lot Lot Lot Lot Lot

7,149,500